CALGARY, ALBERTA–(Marketwired – Feb. 7, 2017) – Raging River Exploration Inc. (“Raging River” or the “Company“) (TSX:RRX) is pleased to present the results of the independent reserves report (the “Sproule Report”) prepared by Sproule Associates Ltd. (“Sproule”) as of December 31, 2016.

During 2016, the Company invested $403.5 million (unaudited) consisting of $192 million of acquisition capital and $211.5 million of development capital into the expansion and development of the Viking play. This invested capital resulted in estimated average annual production of 17,900 boe/d (92% oil) representing year over year production per debt adjusted share growth of 20%. 2016 Proved plus Probable Finding Development and Acquisition (“FD&A”) costs including changes in Future Development Capital (“FDC”) were $19.43 per boe resulting in a Proved plus Probable (“P+P”) recycle ratio of 1.5.

FD&A costs including the change in FDC of $19.43 per boe resulting in a recycle ratio of 1.5 times

Using the independent reserves evaluation effective December 31, 2016, the net present value of future net revenues discounted at 10% (“PV10”) before taxes of our P+P reserves, inclusive of our internally estimated undeveloped land of $171 million and net of estimated net debt of $212 million equates to $8.34 per common share, an increase from $6.83 per common share at December 31, 2015.

A total of 1,166 Viking horizontal wells are included in our PDP reserves.

An additional 1,171 undeveloped locations have been booked leaving approximately 67% of our prospective locations as currently unbooked.

Operations Update:

Fourth quarter 2016 production averaged approximately 20,400 boe/d (92% oil), bringing average 2016 annual production to 17,900 boe/d (92% oil) representing year over year production per debt adjusted share growth of 20%.

The $211.5 million of development capital resulted in 281 net wells drilled during 2016.

For 2017, quarter to date we have drilled approximately 48 net wells (51%) of the 93.5 net wells budgeted for the first quarter of 2017. Field conditions and access to services have been supportive and as a result, we anticipate completing all drilling and completion operations by early March. Total capital expenditures within the first quarter are expected to be $100 million.

Average on-stream costs quarter to date have averaged approximately 5 – 7% higher than the low’s witnessed in 2016. This cost inflation was anticipated within our budget and we remain on track to execute our 2017 budget at previously released levels for the year 2017 of $310 million.

Waterflood execution continues to be a priority in the first quarter with an estimated $20 million being spent on facilities. First waterflood reserves were recorded in 2016 from Sproule with approximately 700 mstb of oil being booked attributable to our ongoing waterfloods.

Extended Reach Horizontal (ERH) Update

We are strongly encouraged by the results of our initial phase of extended reach horizontal (“ERH”) wells drilled in the third and fourth quarters of 2016. To date, we have drilled over 41.5 net ERH wells across our asset base in Saskatchewan and an additional 17 net ERH wells in Alberta. Initial production rates of the ERH wells have exceeded management’s expectations, with the average ERH well seeing approximately two times the initial productivity of the comparable offsetting standard (approximately 600m) laterals. We look forward to providing further updates and quantifying the economic improvements we are achieving as we gain more performance history on the ERH wells.

The following summarizes certain information contained in the Sproule Report. The Sproule Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form which will be filed on SEDAR by the end of March 2017.

Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any royalty interests of the Company.

Based on Sproule’s December 31, 2016 escalated price forecast.

It should not be assumed that the present worth of estimated future net revenue presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of Raging River’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.

Totals may not add due to rounding.

Pursuant to section 5.4.3 “Levels of Certainty for Reported Reserves” of the COGE Handbook, reported reserves should target at least a 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Net Asset Value

December 31, 2016

BTAX NPV 5%

BTAX NPV 10%

($000’s)

$/share(6)

($000’s)

$/share(6)

P+P NPV (1,2)

2,548,372

10.64

1,962,477

8.20

Undeveloped acreage (3)

171,240

0.72

171,240

0.72

Net debt (4)

(212,000)

(0.89)

(212,000)

(0.89)

Proceeds from stock options (5)

75,522

0.32

75,522

0.32

Net Asset Value (fully-diluted)

2,583,134

10.79

1,997,239

8.34

Notes:

Evaluated by Sproule as at December 31, 2016. Net present value of future net revenue does not represent fair market value of the reserves.

Net present values (“NPV”) equals net present value of future net revenue before taxes based on Sproule’s forecast prices and costs as of December 31, 2016.

Internally evaluated with an average value of $400 per acre for 428,100 undeveloped net acres.

Net debt as at December 31, 2016, including working capital deficit (unaudited).

Fully-diluted shares at December 31, 2016 total: including outstanding common shares of 231.1 million and 8.3 million stock options that are in-the-money as at December 31, 2016.

Per share figures based on fully-diluted shares outstanding as at December 31, 2016 – see note 5.

Future Development Costs

The following is a summary of the estimated FDC required to bring P+P undeveloped reserves on production.

Future Development Capital Costs ($000s)

Total
Proved

Total Proved +
Probable

2017

242,726

254,063

2018

183,107

187,586

2019

191,646

202,290

2020

144,174

169,016

Total undiscounted FDC

761,739

813,040

Total discounted FDC at 10% per year

645,758

686,770

Performance Measures(1)

2016

2015

2014

2013

Average crude oil price WTI US$/bbl

43.32

48.80

93.00

97.98

Capital ($000)

403,500

339,191

278,594

272,495

Production boe/d

17,900

13,715

10,755

5,665

Operating netback $/boe

29.76

35.51

64.51

60.07

Proved Producing

Total Reserves mboe

32,991

24,530

19,103

12,004

Reserves additions mboe

15,013

10,433

11,024

9,599

FD&A $/boe(2)

26.88

32.51

25.27

28.39

Recycle Ratio(3)

1.1

1.09

2.55

2.12

Reserves Replacement(4)

229%

208%

281%

464%

RLI (years)(5)

5.1

4.9

4.9

5.8

Proved Plus Probable Producing

Total Reserves mboe

41,673

30,952

23,873

16,908

Reserves additions mboe

17,273

12,085

10,890

12,717

FD&A $/boe(2)

23.36

28.07

25.58

21.43

Recycle Ratio(3)

1.27

1.27

2.52

2.80

Reserves Replacement(4)

264%

241%

277%

615%

RLI (years)(5)

6.4

6.2

6.1

8.2

Total Proven

Total Reserves mboe

71,577

57,391

49,928

31,376

Reserves additions mboe

20,738

12,467

22,466

21,851

Change in FDC ($000)

84,939

(67,100)

262,071

298,429

FD&A $/boe(2)

23.55

21.82

24.07

26.13

Recycle Ratio(3)

1.26

1.63

2.68

2.30

Reserves Replacement(4)

317%

249%

572%

1057%

RLI (years)(5)

11.0

11.5

12.7

15.2

2016

2015

2014

2013

Proven Plus Probable

Total Reserves mboe

93,989

76,361

63,565

42,729

Reserves additions mboe

24,180

17,800

24,750

27,619

Change in FDC ($000)

66,240

(43,900)

305,248

259,940

FD&A $/boe(2)

19.43

16.59

23.59

19.28

Recycle Ratio(3)

1.53

2.14

2.73

3.12

Reserves Replacement(4)

369%

356%

630%

1336%

RLI (years)(5)

14.4

15.3

16.2

20.7

Notes:

Financial and production information is per the Company’s 2016 preliminary unaudited financial statements and is therefore subject to audit.

FD&A costs are used as a measure of capital efficiency. The calculation includes all capital costs for that period plus the change in FDC for that period. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period. For example: 2016 Total Proven = ($403,500,000+$84,939,000) / (71,577mboe-57,391 mboe +6,552 mboe) = $23.55 per boe.

Recycle Ratio is calculated by dividing the operating netback per boe by the FD&A costs for that period. For example: 2016 Total Proven = ($29.76/$23.55) = 1.26. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.

The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2016 Total Proven = (71,577 mboe -57,391 mboe +6,552 mboe)/6,552 mboe = 317%.

RLI is calculated by dividing the reserves in each category by the average annual production for that period. For example 2016 Total Proven = (71,577 mboe) / (17,900 boe*.366) = 11.0 years.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2016, reflected in the Sproule Report. These price assumptions were provided to Raging River by Sproule and were Sproule’s then current forecast at the date of the Sproule Report.

The exchange rate used to generate the benchmark reference prices in this table.

As at December 31, 2016.

General

Our long term business model is robust, defined and is expected to generate meaningful free cashflow and earnings above growth capital. The Company has been built to withstand the volatility in commodity prices and provide meaningful per share growth to our shareholders. Per share growth has and will continue to be accomplished through excellence in execution, selective accretive acquisitions, maintenance of a pristine balance sheet and diligent development of new plays and play extensions.

FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. More particularly, this press release contains statements concerning details of Raging River’s 2017 planned capital program; expectations of commodity prices; guidance relating to 2017 including expectations as to average production; expected details of our 2017 first quarter drilling and completions plans and capital expenditures; expected details relating to our waterflood and ERH well programs; details of our drilling inventory; the expected details of our long-term business model including the expectation that such model can generate meaningful free cash flow and earnings above growth capital; and the expectation thatthe Company can generate per share growth through excellence in execution, selective accretive acquisitions, maintenance of a pristine balance sheet and diligent development of new plays and play extensions. In addition, the use of any of the words “guidance”, “initial, “scheduled”,“can”, “will”, “prior to”, “estimate”, “anticipate”, “believe”, “should”, “unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, and similar expressions are intended to identify forward-looking statements. The forward-looking statementscontained herein are based on certain key expectations and assumptions made by the Company, including, but not limitedto, expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, pipeline, transportation and processing capacity, receipt of requiredregulatory approval, the success of future drilling and development activities, the performance of existing wells, theperformance of new wells, Raging River’s growth strategy, general economic conditions, availability of required equipmentand services and the costs of obtaining such equipment and services, and expectations as to commodity prices. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects, capital expenditures, acquisitions or other corporate transactions; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, Raging River’s expectations and plans for its 2017 capital program and its 2017guidance may change as circumstances change and as different opportunities arise, such as acquisition opportunities, and as the Company continues to evaluate its drilling results and opportunities. To the extent any guidance or forward looking statements herein constitute a financial outlook, they are included herein to provide readers with an understanding of management’s plans and assumptions for budgeting purposes and readers are cautioned that the information may not be appropriate for other purposes. Additional information on these and other factors that could affect Raging River’s operations and financial results are included in the Company’s Annual Information Form and other reports on file with Canadian securities regulatory authorities, which may be accessed through the SEDAR website (www.sedar.com).

The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

BARRELS OF OIL EQUIVALENT: The term “boe” or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

OIL AND GAS METRICS: This press release contains a number of oil and gas metrics, including FD&A, recycle ratio, reserves replacement, and reserves life index or RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

DRILLING LOCATIONS: This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as “booked locations”, are derived from the Company’s most recent independent reserves evaluation as prepared by Sproule as of December 31, 2016 and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 3,600 drilling locations identified herein, 1,100 are proved locations, 71 are probable locations and 2,429+ are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, and engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

INITIAL PRODUCTION RATES; References in this press release to initial production rates, and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.

NON-IFRS MEASURES: This document contains the terms “funds flow from operations”, “net debt”, “operating netback”, and “funds flow netback” that do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds flow from operations, which is presented before the change in non-cash operating working capital, to analyze operating performance and leverage. Management believes “net debt” is a useful supplemental measure of the total amount of current and long-term debt of the Company. Mark-to-market risk management contracts are excluded from the net debt calculation. Management believes “operating netback” is a useful supplemental measure of the amount of revenues received after royalties and operating and transportation costs and “funds flow netback” is a useful supplemental measure of the amount of revenues received after the royalties, operating, transportation costs, general and administrative costs, financial charges and asset retirement obligations. Additional information relating to these non-IFRS measures, including the reconciliation between funds flow from operations and cash flow from operating activities, can be found in the Company’s most recent management’s discussion and analysis, which may be accessed through the SEDAR website (www.sedar.com).